Minutes Frequency Response Initiative Meeting

Transcription

1 Minutes Frequency Response Initiative Meeting April 27, 2010 Tucson Electric Co. Office Tucson, Arizona A meeting of the NERC Frequency Response Initiative Team was held on April 27, 2010 at the Ameren Corporation Office in St. Louis, Missouri. The agenda, and attendance list are attached as Exhibits A and B, respectively. There are no individual statements or minority opinions. Bob Cummings, NERC Director of System Analysis and Reliability Initiatives presided over the meeting. NERC Frequency Response Initiative Appreciation for Meeting Host Ameren Corporation The Frequency Response Initiative Team acknowledges and appreciates the hospitality that the Ameren Corporation and specifically Gerry Beckerle and Crystal Ward provided to the subcommittee as it hosted the Frequency Response Initiative meeting at their facility. Antitrust Compliance Guidelines Director Bob Cummings acknowledged the NERC Antitrust Compliance Guidelines. Frequency Response Initiative Terminology The Frequency Response Initiative Team reviewed the current and proposed frequency related terms, definitions, and frequency events and recovery sequence of events. The team discussed and drafted terminology to be used by the electric power industry for common understanding and use, see (Exhibit C). Frequency Response Initiative Surveys The Frequency Response Initiative Team will develop at least two surveys to gather data and information to support the frequency response analysis, conclusion, and recommendations. The two identified surveys are: Survey to attain knowledge on how Balancing Authorities calculate their frequency response. This survey will be completed in three months. Survey to attain generating unit(s) governor use, control, settings, and characteristics. This survey will be completed in six months Village Blvd. Princeton, NJ

2 The Frequency Response Initiative Survey Development Team will include the following: Bob Cummings Terry Bilke Sydney Niemeyer Bill Herbsleb Don Badley John Tolo Mike Potishnak Gerry Beckerle Larry Akens Frequency Response Initiative Overview Bob Cummings took all information attained and combined it with his previously developed initiative criteria and developed an enhanced Overview of the Frequency Response Initiative. The Overview will be presented to the NERC Board of Trustees at the May 2010 meeting. Key sections of the Overview are: Introduction Objectives of the Initiative Initiative Tasks Near-Term Tasks expected to be completed in six months Mid-Term Tasks expected to be completed in nine months Long-Term Tasks expected to be completed in one to wwo years Ongoing Tasks Frequency Response and Control Terminology Dates and Locations of Future Meetings Additional meetings or conference calls may be scheduled as necessary for ADITF business-related purposes. Tuesday, May 4, 2010 Wednesday, May 5, a.m. 5 p.m. 8 a.m. 5 p.m. Chicago, IL Host: NERC Contact: Darrel Richardson Respectfully submitted, Tom Vandervort Thomas J. Vandervort Resources Subcommittee Secretary Resources Subcommittee Meeting Minutes April 28,

3 Exhibit A Agenda Frequency Response Initiative April 27, 2010 St. Louis, Missouri 1. Introductions What is MINASPIFRISPI? 2. Anti Trust Guidelines 3. Agenda Review 4. Freqeuency Response Initiative Overview a. Initiative Tasks are there others? b. Task Responsibilities which group(s) have the lead? c. BAL-003 Request for Rehearing 5. Terminology Catalogue common terminology to be used in FRI 6. Drafting Team Updates 7. Recommendation Alert a. Discuss elements to be included in the Alert b. Schedule of the Alert 8. Detailed Review of FRI Tasks Near-Term Tasks Completed in Six Months 1. Issue a Recommendation and a survey in accordance with Section 810 of NERC s Rules of Procedure to in order to collect data to evaluate how frequency response should be addressed. 2. Based on the data received, analyze current and historical primary control frequency response performance and determine what factors influence that performance Village Blvd. Princeton, NJ

4 3. Based on the data received, analyze current and historical secondary control performance and determine what factors influence that performance. 4. Develop an automated method for determining frequency deviation events that should be used for Balancing Authorities to determine their primary control frequency Response. 5. Develop sustainable methods for automatically collecting, trending, and analyzing the various elements of frequency response and control. 6. Improve transient and mid-term dynamic models of generator primary frequency response. Long-Term Tasks Completed in One Year 1. Explore and analyze what are appropriate frequency response and control performance requirements to maintain system reliability. 2. Determine appropriate minimum Bias settings for use in AGC systems as part of an overall frequency response and control strategy. 3. Analyze current Inertial Response performance and determine what factors influence that performance. 4. Explore how displacement of inertial generation with electronically-coupled resources might influence Inertial Response. 5. Examine Primary Control Frequency Response characteristics of electronicallycoupled resources and smart grid loads. Appropriate load and generator models must be developed to properly analyze their influence on system behavior in transient, post-transient, and mid-term stability. 9. Future Meetings & Schedule 2

5 Exhibit B Meeting Notes NERC Frequency Response Initiative April 27, 2010 Ameren General Office Building St. Louis, Missouri Attendance David Hilt Robert Cummings Terry Bilke Bill Herbsleb Steve Myers Howard Illian Darrel Richardson Doug Hils Sydney Niemeyer Tony Nguyen Don Badley John Tolo Jerry Rust Mark Prosperi-Porta Phil Tatro Larry Akens LeRoy Patterson Carlos Martinez Mike Potishnak Tom Siegrist Mike Oatts Glenn Stephens Steve Crutchfield Gerry Beckerle Andy Rodriquez James Murphy Mahmood Mirheydar Robert Rhodes Tom Vandervort Village Blvd. Princeton, NJ

6 Exhibit C Frequency Response Initiative Draft Terminology as of Frequency Response and Control This is the over-arching descriptor for the response and control actions that span from when a frequency deviation begins until frequency is recovered. Point A The first significant change in frequency of a frequency event, which occurs at time zero (Scan T). A significant change in frequency is defined as: ±36 mhz for the Eastern Interconnection, ±50 mhz for the Western Interconnection, ±70 mhz for the Texas Interconnection, and ± mhz for the Quebec Interconnection. Initial Frequency (Value A) The average actual (not scheduled) pre-perturbation frequency. Value A is defined as the average frequency prior to Point A based on a sample of 10 to 16 seconds, depending on the EMS Scan Rate of the BA as shown below, where T is the first scan that defines Point A. EMS Scan Rate (seconds) 6 s 5 s 4 s 3 s 2 s Scans Used to Determine Value A T minus 2 T minus 2 T minus 8 T minus 5 T minus 8 # of Seconds in Sample Arrested Frequency Value C Point C The point of lowest frequency in the first swing of the frequency excursion between time zero (Point A) and time zero plus 20 seconds. Arresting Period The period of time from time zero (Point A) to the time of Point C. Arresting Period Frequency Response A combination of Inertial Response and the initial Primary Control Response acting together to limit the duration and magnitude of frequency change during the Arresting Period. At Point A, the entire response is inertial, and by Point C (where Village Blvd. Princeton, NJ

7 equilibrium has been established and frequency arrested), the inertial contribution is at zero. Depending on the type of trip, (e.g., an instantaneous electrical trip of the generator; or a turbine trip, where the generator trips at a later time after by reverse power; or other time tripping), the Primary Control Response may be initiated and contributing to the Arresting Period Frequency Response at Point C. Rebound Period The period of time from the time of Point C to time zero plus 20 seconds. Rebound Period Frequency Response The remaining portion of Primary Control Response delivered during the Rebound Period without any external intervention. During the Rebound Period, Primary Control Response begins to restore inertia expended as Inertial Response. The Rebound Period Frequency Response generally does not include Secondary Control Response, as typical Secondary Control performance occurs more than 35 to 40 seconds following Point A. In order to avoid the possibility of creating control-based instability, Automatic Secondary Control Response (such as AGC) should not be applied until the Primary Control Response has stabilized. Settling Period The period of time from the time of Point C to the time of Point B. Point B The point at which Primary Control Response has been damped (stabilized). Settled Frequency Value B The average actual (not scheduled) frequency following the Arresting Period. Value B is defined as the average frequency following Point C based on a sample of 28 to 34 seconds, depending on the EMS Scan Rate of the BA as shown below, where T is the first scan that defines Point A. EMS Scan Rate (seconds) 6 s 5 s 4 s 3 s 2 s Scans Used to Determine Value A T plus 4 through T plus 8 T plus 5 through T plus 10 T plus 6 through T plus 12 T plus 7 through T plus 17 T plus 10 through T plus 26 # of Seconds in Sample Recovery Period The period of time from time zero plus 53 seconds to the time of the return of frequency to within pre-establish ranges of reliable continuous operation. Primary Control Actions provided by the Interconnection to arrest frequency in response to a frequency event (disturbance). Primary Control comes from generator governor response, load 2

8 response (typically from motors), and other devices that provide an immediate response based on local (device-level) control systems. Secondary Control Actions provided by an individual BA or its Reserve Sharing Group intended to replace Primary Control Response and restore frequency from the Arrested Frequency back to Scheduled Frequency. Secondary Control comes from either manual or automated dispatch from a centralized control system. Tertiary Control Actions provided by Balancing Authorities on a balanced basis that are expected to have a net zero effect on ACE. Examples of Tertiary Control include dispatching generation to serve native load; dispatching generation to effect Interchange; and redispatching generation. Inertial Response The power delivered by the Interconnection in response to any change in frequency due to the rotating mass of machines synchronously connected to the BPS, including both load and generation. Primary Control Response The power delivered by the Interconnection in response to a frequency event (disturbance) through generator governor response, load response (typically from motors), and other devices that provide an immediate response to frequency based on local (device-level) control systems, without human or remote intervention. Primary Control Response Withdrawal The withdrawal of previously delivered Primary Control Response, either through local Primary Control actions (such as plant internal control) or though Secondary Control action (such as AGC). Secondary Control Response The power delivered by a Balancing Authority or Reserve Sharing Group in response to a frequency event (disturbance) through Secondary Control actions, such as manual or automated dispatch from a centralized control system. Secondary control actions are intended to replace Primary Control Response and restore frequency from the Arrested Frequency back to Scheduled Frequency. Recovery of Frequency Responsive Reserves This is the redispatch of generation and scheduling of interchange to recover the required frequency responsive reserves of the interconnection in preparation for the next event. 3